Tool for azimuthal resistivity measurement and bed boundary detection

ABSTRACT

Systems and methods for performing bed boundary detection and azimuthal resistivity logging with a single tool are disclosed. Some method embodiments include logging a borehole with an azimuthally-sensitive resistivity logging tool; deriving both a resistivity log and a boundary detection signal from measurements provided by said tool; and displaying at least one of the boundary detection signal and the resistivity log. The resistivity log measurements may be compensated logs, i.e., logs derived from measurements by one or more symmetric transmitter-receiver arrangements. Though symmetric arrangements can also serve as the basis for the boundary detection signal, a greater depth of investigation can be obtained with an asymmetric arrangement. Hence the boundary detection signal may be uncompensated.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a divisional application of parent U.S. patent application Ser. No. 11/835,619, filed Aug. 8, 2007, by Michael Bittar, which claims priority to Prov. U.S. Patent App. 60/821,721, filed Aug. 8, 2006, and titled “Processing Resistivity Logs” by inventor Michael Bittar, and to Prov. U.S. Patent App. 60/821,988, filed Aug. 10, 2006, and titled “Tool for Azimuthal Resistivity Measurement and Bed Boundary Detection” by the same inventor. In addition, the parent application is a continuation-in-part of:

-   -   issued U.S. Pat. No. 7,265,552, filed Jul. 14, 2006, and titled         “Electromagnetic Wave

Resistivity Tool Having a Tilted Antenna for Geosteering Within a Desired Payzone,” which is a continuation of

-   -   issued U.S. Pat. No. 7,138,803, filed Aug. 5, 2005, which is a         continuation of     -   issued U.S. Pat. No. 7,019,528, filed Jul. 9, 2003, which is a         continuation of     -   issued U.S. Pat. No. 6,911,824, filed Sep. 25, 2002, which is a         continuation of     -   issued U.S. Pat. No. 6,476,609, filed Jul. 13, 2000, which is a         continuation-in-part of     -   issued U.S. Pat. No. 6,163,155, filed Jan. 28, 1999.         Finally, the parent application relates to co-pending U.S.         patent application Ser. No. 12/373,558, with title “Resistivity         Logging with Reduced Dip Artifacts” which is a US national stage         application of PCT/US2007/075455, filed Aug. 8, 2007 by inventor         Michael Bittar. Each of the foregoing patents and applications         is hereby incorporated herein by reference.

BACKGROUND

The gathering of downhole information has been done by the oil industry for many years. Modern petroleum drilling and production operations demand a great quantity of information relating to the parameters and conditions downhole. Such information typically includes the location and orientation of the borehole and drilling assembly, earth formation properties, and drilling environment parameters downhole. The collection of information relating to formation properties and conditions downhole is commonly referred to as “logging”, and can be performed during the drilling process itself.

Various measurement tools exist for use in wireline logging and logging while drilling. One such tool is the resistivity tool, which includes one or more antennas for transmitting an electromagnetic signal into the formation and one or more antennas for receiving a formation response. When operated at low frequencies, the resistivity tool may be called an “induction” tool, and at high frequencies it may be called an electromagnetic wave propagation tool. Though the physical phenomena that dominate the measurement may vary with frequency, the operating principles for the tool are consistent. In some cases, the amplitude and/or the phase of the receive signals are compared to the amplitude and/or phase of the transmit signals to measure the formation resistivity. In other cases, the amplitude and/or phase of the receive signals are compared to each other to measure the formation resistivity.

When plotted as a function of depth or tool position in the borehole, the resistivity tool measurements are termed “logs” or “resistivity logs”. Such logs may provide indications of hydrocarbon concentrations and other information useful to drillers and completion engineers. In particular, azimuthally-sensitive logs may provide information useful for steering the drilling assembly. However, there exist limitations on the size and length of the drilling assembly which may limit the number of logging tools that can be included, and hence may limit the types of measurements that can be logged.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the various disclosed embodiments, reference will now be made to the accompanying drawings in which:

FIG. 1 shows an illustrative logging while drilling environment;

FIG. 2 shows an illustrative resistivity logging tool in accordance with some invention embodiments;

FIG. 3 shows a coordinate system for describing antenna orientation;

FIG. 4 shows a flow chart of an illustrative logging method;

FIG. 5 shows a simulated logging environment having multiple beds with differing resistivities;

FIG. 6 shows an illustrative set of azimuthal bins;

FIG. 7 shows an illustrative conversion between phase and resistivity;

FIG. 8 shows azimuthally-sensitive logs for the simulated environment in FIG. 5; and

FIG. 9 shows azimuthally-sensitive logs for an anisotropic formation that is otherwise similar to the simulated environment in FIG. 5.

While the described embodiments are susceptible to various modifications and alternative forms, specific examples thereof are shown for illustrative purposes and will be described in detail below. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the claims to the particular examples described, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

NOTATION AND NOMENCLATURE

Certain terms are used throughout the following description and claims to refer to particular system components and configurations. As one skilled in the art will appreciate, companies may refer to a component by different names. This document does not intend to distinguish between components that differ in name but not function. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Also, the term “couple” or “couples” is intended to mean either an indirect or a direct electrical connection. Thus, if a first device couples to a second device, that connection may be through a direct electrical connection, or through an indirect electrical connection via other devices and connections. In addition, the term “attached” is intended to mean either an indirect or a direct physical connection. Thus, if a first device attaches to a second device, that connection may be through a direct physical connection, or through an indirect physical connection via other devices and connections.

DETAILED DESCRIPTION

The issues identified in the background are at least partly addressed by systems and methods for performing bed boundary detection and azimuthal resistivity logging with a single tool. Some method embodiments include logging a borehole with an azimuthally-sensitive resistivity logging tool; deriving both a resistivity log and a boundary detection signal from measurements provided by said tool; and displaying at least one of the boundary detection signal and the resistivity log. The resistivity log measurements may be compensated logs, i.e., logs derived from measurements by one or more symmetric transmitter-receiver arrangements. Though symmetric arrangements can also serve as the basis for the boundary detection signal, a greater depth of investigation can be obtained with an asymmetric arrangement. Hence the boundary detection signal may be uncompensated.

To illustrate a context for the disclosed systems and methods, FIG. 1 shows a well during drilling operations. A drilling platform 2 is equipped with a derrick 4 that supports a hoist 6. Drilling of oil and gas wells is carried out by a string of drill pipes connected together by “tool” joints 7 so as to form a drill string 8. The hoist 6 suspends a kelly 10 that lowers the drill string 8 through rotary table 12. Connected to the lower end of the drill string 8 is a drill bit 14. The bit 14 is rotated and drilling accomplished by rotating the drill string 8, by use of a downhole motor near the drill bit, or by both methods.

Drilling fluid, termed mud, is pumped by mud recirculation equipment 16 through supply pipe 18, through drilling kelly 10, and down through the drill string 8 at high pressures and volumes to emerge through nozzles or jets in the drill bit 14. The mud then travels back up the hole via the annulus formed between the exterior of the drill string 8 and the borehole wall 20, through a blowout preventer, and into a mud pit 24 on the surface. On the surface, the drilling mud is cleaned and then recirculated by recirculation equipment 16.

For logging while drilling (LWD), downhole sensors 26 are located in the drillstring 8 near the drill bit 14. Sensors 26 include directional instrumentation and a modular resistivity tool with tilted antennas for detecting bed boundaries. The directional instrumentation measures the inclination angle, the horizontal angle, and the azimuthal angle (also known as the rotational or “tool face” angle) of the LWD tools. As is commonly defined in the art, the inclination angle is the deviation from vertically downward, the horizontal angle is the angle in a horizontal plane from true North, and the tool face angle is the orientation (rotational about the tool axis) angle from the high side of the well bore. In some embodiments, directional measurements are made as follows: a three axis accelerometer measures the earth's gravitational field vector relative to the tool axis and a point on the circumference of the tool called the “tool face scribe line”. (The tool face scribe line is drawn on the tool surface as a line parallel to the tool axis.) From this measurement, the inclination and tool face angle of the LWD tool can be determined. Additionally, a three axis magnetometer measures the earth's magnetic field vector in a similar manner. From the combined magnetometer and accelerometer data, the horizontal angle of the LWD tool can be determined. In addition, a gyroscope or other form of inertial sensor may be incorporated to perform position measurements and further refine the orientation measurements.

In a some embodiments, downhole sensors 26 are coupled to a telemetry transmitter 28 that transmits telemetry signals by modulating the mud flow in drill string 8. A telemetry receiver 30 is coupled to the kelly 10 to receive transmitted telemetry signals. Other telemetry transmission techniques are well known and may be used. The receiver 30 communicates the telemetry to a surface installation (not shown) that processes and stores the measurements. The surface installation typically includes a computer system of some kind, e.g. a desktop computer, that may be used to inform the driller of the relative position and distance between the drill bit and nearby bed boundaries.

The drill bit 14 is shown penetrating a formation having a series of layered beds 34 dipping at an angle. A first (x,y,z) coordinate system associated with the sensors 26 is shown, and a second coordinate system (x″,y″,z″) associated with the beds 32 is shown. The bed coordinate system has the z″ axis perpendicular to the bedding plane, has the y″ axis in a horizontal plane, and has the x″ axis pointing “downhill”. The angle between the z-axes of the two coordinate systems is referred to as the “dip” and is shown in FIG. 1 as the angle β.

Referring now to FIG. 2, an illustrative resistivity tool 102 is shown. The tool 102 is provided with one or more regions of reduced diameter for suspending a wire coil. The wire coil is placed in the region and spaced away from the tool surface by a constant distance. To mechanically support and protect the coil, a non-conductive filler material (not shown) such as epoxy, rubber, fiberglass, or ceramics may be used to fill in the reduced diameter regions. The transmitter and receiver coils may comprise as little as one loop of wire, although more loops may provide additional signal power. The distance between the coils and the tool surface is preferably in the range from 1/16 inch to ¾ inch, but may be larger.

The illustrated resistivity tool 102 has six coaxial transmitters 106 (T5), 108 (T3), 110 (T1), 116 (T2), 118 (T4), and 120 (T6), meaning that the axes of these transmitters coincide with the longitudinal axis of the tool. In addition, tool 102 has three tilted receiver antennas 104 (R3), 112 (R1), and 114 (R2). The term “tilted” indicates that the plane of the coil is not perpendicular to the longitudinal tool axis. (FIG. 3 shows an antenna that lies within a plane having a normal vector at an angle of θ with the tool axis and at an azimuth of a with respect to the tool face scribe line. When θ equals zero, the antenna is said to be coaxial, and when θ is greater than zero the antenna is said to be tilted.) The spacing of the antennas may be stated in terms of a length parameter x, which in some embodiments is about 16 inches. Measuring along the longitudinal axis from a midpoint between the centers of receiver antennas 112 and 114, transmitters 110 and 116 are located at ±1x, transmitters 108 and 118 are located at ±2x, and transmitters 106 and 120 are located at ±3x. The receiver antennas 112 and 114 may be located at ±x/4. In addition, a receiver antenna 104 may be located at plus or minus 4x.

The length parameter and spacing coefficients may be varied as desired to provide greater or lesser depth of investigation, higher spatial resolution, or higher signal to noise ratio. However, with the illustrated spacing, symmetric resistivity measurements can be made with 1x, 2x, and 3x spacing between the tilted receiver antenna pair 112, 114, and the respective transmitter pairs 110 (T1), 116 (T2); 108 (T3), 118 (T4); and 106 (T5), 120 (T6). In addition, asymmetric resistivity measurements can be made with 1x, 2x, 3x, 5x, 6x, and 7x spacing between the tilted receiver antenna 104 and the respective transmitter 106, 108, 110, 116, 118, and 120. This spacing configuration provides tool 102 with some versatility, enabling it to perform deep (but asymmetric) measurements for bed boundary detection and symmetric measurements for accurate azimuthal resistivity determination.

In some contemplated embodiments, the transmitters may be tilted and the receivers may be coaxial, while in other embodiments, both the transmitters and receivers are tilted, though preferably the transmitter and receiver tilt angles are different. Moreover, the roles of transmitter and receiver may be interchanged while preserving the usefulness of the measurements made by the tool. In operation, each of the transmitters are energized in turn, and the phase and amplitude of the resulting voltage induced in each of the receiver coils are measured. From these measurements, or a combination of these measurements, the formation resistivity can be determined.

In the illustrated embodiment of FIG. 2, the receiver coils are tilted with a 45° angle between the normal and the tool axis. Angles other than 45° may be employed, and in some contemplated embodiments, the receiver coils are tilted at unequal angles or are tilted in different azimuthal directions. The tool 102 is rotated during the drilling (and logging) process, so that resistivity measurements can be made with the tilted coils oriented in different azimuthal directions. These measurements may be correlated with tool orientation measurements to enable detection of boundary distances and directions.

FIG. 4 shows a flowchart of an illustrative method for generating a resistivity log and bed boundary indicator using the tool of FIG. 2. This method may be performed by a processor in the tool alone or in cooperation with a surface computing facility. Beginning in block 402, a first transmitter is selected. The order in which the transmitters are selected may be designed to minimize the effects of motion on measurements that are to be combined. Thus, for example, transmitters 106 and 120 may be adjacent in the transmitter firing sequence, as may transmitters 108 and 118, and transmitters 110 and 116. Thus when the measurements resulting from the energizing of these transmitter pairs may be combined while requiring minimal or no compensation for tool motion between the firing times of these transmitters.

In block 404 the selected transmitter is energized, and in block 406 the amplitude and phase of the induced receiver voltages are measured. For receiver 104, the amplitude and phase may be measured relative to the voltage signal being applied to the selected transmitter. For receivers 112 and 114, the amplitude and phase may be measured in the same way, or alternatively, the amplitude and phase of one receiver (e.g. 112) may be measured relative to the other receiver (e.g., 114).

In block 408, the tool position and orientation during the amplitude and phase measurements are determined. This position determination may include tool orientation and eccentricity, but at a minimum it includes a determination of the tool's depth or position along the length of the borehole so as to permit later correlation with independent measurements of formation properties from other sources. Tool position may be made using inertial tracking instruments (e.g., accelerometers and gyroscopes), while orientation information may be determined from magnetic field sensors and gravitational field sensors, alone or in combination with inertial tracking instruments. Eccentricity measurements may be made using a borehole caliper tool. In some environments the tool's motion along the borehole (when being withdrawn from the hole) may approach 2 meters/second, while the tool's rotational velocity (during drilling operations) may approach 200 revolutions per minute. To prevent the tool's motion from significantly affecting spatial resolution of the measurements, the measurement period for each transmitter firing is preferably kept below 10 milliseconds.

For display of the resistivity and bed boundary measurements, the borehole surface may be conceptually divided into a grid of “bins”. Along the length of the borehole, the grid is evenly divided into sections of the desired vertical resolution. Similarly, in the circumferential direction, the grid is divided into sections of the desired azimuthal resolution. (FIG. 6 shows an illustrative division of the borehole circumference into eight azimuthal sections 602-616.) For each of the bins resulting from this division, it is expected that the logging tool 102 will provide multiple measurements in each bin, assuming reasonable grid dimensions relative to the spatial resolution of the tool 102. Accordingly, in block 410, the amplitude and phase measurements are stored in the appropriate bin. The bin for a given transmitter-receiver measurement may be selected based on the rotational orientation of the tool and the position of the midpoint between transmitter and receiver or, where multiple transmitters and/or receivers are used concurrently, the midpoint between the effective transmitter position and the effective receiver position.

In block 412, a resistivity measurement and a bed boundary indicator measurement are determined or updated for the bin based on the new amplitude and phase measurement and any previous measurements in that bin. Due to the tilted receiver (and/or tilted transmitter) antennas, the resistivity measurements are azimuthally sensitive. The resistivity measurements are determined from the average compensated amplitude and phase measurement of the current bin, possibly in combination with the average compensated measurements for other nearby bins and other measured or estimated formation parameters such as formation strike, dip, and anisotropy. The compensated measurements are determined by averaging measurements resulting from symmetrically spaced transmitters. For example, if the phase differences between receivers 112 (R1), 114 (R2) in response to the first and second transmitters 110 (T1), 116 (T2) are expressed as: δ_(T1)=Φ_(R1T1)−Φ_(R2T1)  (1) δ_(T2)=Φ_(R2T2)−Φ_(R1T2),  (2) then the compensated phase difference is: δ_(C)=(δ_(T1)+δ_(T1))/2.  (3) This compensated phase difference is averaged with the other compensated phase differences in a bin for the 1x transmitter spacing. The formation resistivity measurement for that bin may be based on the average compensated phase difference in that bin, on the average compensated phase differences for the 2x and 3x transmitter spacings in that bin, and on the average compensated amplitude ratios for all three transmitter spacing measurements in that bin. (The compensated amplitude ratios can be determined using the following equations in place of equations (1) and (3). a _(T1)=ln(A _(R1T1))−ln(A _(R2T1))  (4) a _(T2)=ln(A _(R2T2))−ln(A _(R1T2))  (5) a _(C)=(a _(T1) +a _(T1))/2,  (6) where, e.g., A_(R1T2) is the amplitude of the signal received by R1 in response to T2.)

The average compensated phase and amplitude measurements from azimuthally spaced and axially spaced bins may also be included in the resistivity calculation to account for the effects of anisotropic, dipping formations. Conventional look-up table or forward modeling techniques may be used to determine the resistivity measurement. An illustrative conversion of phase measurement to resistivity is shown in FIG. 7, but in practice, the conversion typically involves multiple parameters.

The bed boundary indicator calculations for a bin may be based on the longest transmitter-receiver spacing measurements, e.g., receiver 104's (R3) response to transmitter 118 (T4) and/or 120 (T6). For example, if, given the measurements in a bin, the average measured signal phase of receiver 104 relative to the excitation signal of transmitter 120 is Φ_(R3T6), the bed boundary indicator may be calculated as: I=(Φ_(R3T6) in the current bin)−(Φ_(R3T6) in the bin 180° from current bin)  (7) Thus, with reference to FIG. 6, the bed boundary indicator for bin 602 may calculated from the difference in average measured signal phase between bins 602 and 610. The bed boundary indicator for bin 604 may be calculated using a difference between phase measurements for bins 604 and 612. Alternatively, a difference in logarithms of amplitude (attenuation) of receiver 104's response relative to the transmitter 120 signal between these bins may be used instead of phase differences: I=ln(A _(R3T6) in the current bin)−ln(A _(R3T6) in the bin 180° from current bin)  (8) As yet another alternative, rather than taking a difference between phase or log amplitude of bins 180° apart, the difference may be determined between the phase (or log amplitude) for the current bin and the average phase (or log amplitude) for all the bins at a given axial position in the borehole:

$\begin{matrix} {I = {\left( {\Phi_{R\; 3T\; 6}\mspace{14mu}{in}\mspace{14mu}{{bin}\left( {k,z} \right)}} \right) - {\frac{1}{n}{\sum\limits_{i = {1 - n}}\left( {\Phi_{R\; 3T\; 6}\mspace{14mu}{in}\mspace{14mu}{{bin}\left( {i,z} \right)}} \right)}}}} & (9) \\ {I = {{\ln\left( {A_{R\; 3T\; 6}\mspace{14mu}{in}\mspace{14mu}{{bin}\left( {k,z} \right)}} \right)} - {\frac{1}{n}{\sum\limits_{i = {1 - n}}{\ln\left( {A_{R\; 3T\; 6}\mspace{14mu}{in}\mspace{14mu}{{bin}\left( {i,z} \right)}} \right)}}}}} & (10) \end{matrix}$ where bin(k,z) is the bin at the kth rotational position at the zth longitudinal position in the borehole. It is likely that measurements can be repeated many times for each bin and the phase/amplitude values used are actually averages of these repeated measurements.

Returning to FIG. 4, the resistivity measurement and bed boundary indicator are communicated to a user in block 414. The measurement and indicator may be displayed as a function of tool position and azimuthal orientation, preferably while logging (and drilling) operations are ongoing, enabling the user to steer the drilling assembly with the benefit of this information. The display may be updated as each measurement is made, or alternatively, may be updated in stages, i.e., after a sufficient number of measurements have been acquired for a given tool position. In block 416, a check is made to determine if there are more transmitters to be selected in the current firing cycle, and if so, the next transmitter in the firing order is selected in block 418. If not, a check is made in block 420 to determine whether the logging operations are complete, and if not, the next firing cycle is started in block 402. Otherwise the method terminates.

FIG. 5 shows an illustrative logging environment used to simulate the operation of logging tool 102. Logging tool 102 is penetrating a formation having three beds 504-508 at a relative dip angle of 60°. Beds 504 and 508 have a resistivity of 1 Ωm, and sandwiched between them is a 50 foot-thick bed 506 having a resistivity of 20 Ωm. In the first simulation, the resistivity of these beds is assumed to be isotropic. FIG. 8 shows the logs of the bed boundary indicator (on the left) and the azimuthal resistivity (on the right). The azimuthal orientation of the tool is measured from the top of the borehole. (The tool is illustrated with an azimuthal orientation of 0°.)

At an azimuth of 0, the bed boundary indicator starts off at zero, and as the tool approaches the boundary between beds 504 and 506, the indicator increases, indicating that the receiver antenna is tilted toward an approaching boundary with a bed having a higher resistivity than the current bed. As the boundary passes, the indicator drops back to zero, until the tool approaches the boundary between beds 506 and 508. There the indicator drops, indicating that the receiver antenna is tilted towards an approaching boundary having a lower resistivity than the current bed. As the boundary passes, the indicator drops back to zero. A similar, though weaker, response is visible at the 45° azimuth. At 90° azimuth, the indicator is uniformly zero, indicating that no boundary is being approached in that direction. At 135° and 180°, the indicator mirrors the response at 45° and 0°, respectively. A driller seeking to enter and remain in a high-resistivity bed would steer away from the directions in which the tilted antenna produces a negative bed boundary indicator value, and towards those directions that produce a positive indicator value. Of course, allowances should be made for limited turning radius and the desire for shallow approach angles. As can be seen in FIG. 9, anisotropy does not significantly affect the behavior of the bed boundary indicators.

In FIG. 8, the azimuthal resistivity measurements are closely aligned in the isotropic formations, departing from one another only at the bed boundaries. However, in anisotropic formations, the azimuthal resistivity measurements diverge as seen in FIG. 9 because the apparent resistivity depends on the alignment between the tilted receiver and the axis of anisotropy. An inversion technique may be used to exploit this divergence to determine vertical resistivity, horizontal resistivity, and formation dip. Thus the disclosed tool can be used both as a resistivity tool and as a tool for geosteering.

Though FIGS. 8 and 9 have been shown using multiple curves, the data can also be presented in the form of an image. The image may display pixels at different positions along a depth axis and along an azimuthal axis, with color or intensity representing the magnitude of the resistivity or boundary detection measurements. A standard two-dimensional “borehole wall image” style may be adopted, in which the image represents an “unrolled” borehole wall surface. Alternatively, a three-dimensional “virtual reality” style may be preferred, in which the borehole is displayed as a three-dimensional object as seen from a user-adjustable viewpoint.

Though the focus of the examples above has been mainly on the use of phase difference measurements, attenuation measurements can be alternatively or additionally used to determine resistivity and bed boundary indications. While the present invention has been described with respect to a limited number of embodiments, those skilled in the art will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of this present invention. 

What is claimed is:
 1. A logging method that comprises: logging a borehole with an azimuthally-sensitive resistivity logging tool; deriving a boundary detection signal from an azimuthal dependence of measurements provided by said tool; deriving a resistivity log from measurements provided by said tool; and displaying at least one of the boundary detection signal and the resistivity log.
 2. The logging method of claim 1, wherein the resistivity log is derived from measurements made by a symmetric transmitter-receiver arrangement in said tool.
 3. The logging method of claim 2, wherein the boundary detection signal is derived from measurements made by an asymmetric transmitter-receiver arrangement in said tool.
 4. The logging method of claim 2, wherein the symmetric transmitter-receiver arrangement comprises a pair of tilted receivers equally spaced from a midpoint between two coaxial antennas.
 5. A logging system that comprises: a logging tool that obtains resistivity measurements as a function of tool position and orientation; and a processor that processes an azimuthal dependence of at least some of said measurements to determine a bed boundary indicator signal.
 6. The logging system of claim 5, wherein a subset of said measurements are made by symmetric transmitter-receiver arrangement in said tool, and wherein the processor generates a resistivity log based at least in part on this subset.
 7. The logging system of claim 6, wherein a second subset of said measurements are made by an asymmetric transmitter-receiver arrangement in said tool, and wherein the processor derives the bed boundary indicator signal based at least in part on this second subset.
 8. The logging system of claim 6, wherein the symmetric transmitter-receiver arrangement comprises a pair of tilted receivers equally spaced from a midpoint between two coaxial transmit antennas. 